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form10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2010
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-31447

____________________________

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

Texas	74-0694415
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1111 Louisiana
Houston, Texas 77002	(713) 207-1111
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)

____________________________

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of July 26, 2010, CenterPoint Energy, Inc. had 421,716,690 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2010

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PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2009 and 2010 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2009 and June 30, 2010 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2009 and 2010 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42

Item 4.	Controls and Procedures	43

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54

Item 5.	Other Information	54

Item 6.	Exhibits	55

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words "anticipate," "believe," "continue," "could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective," "plan," "potential," "predict," "projection," "should," "will" or other similar words.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements:

•

the resolution of the true-up proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;

•

state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;

•

other state and federal legislative and regulatory actions or developments affecting various aspects of our business, including, among others, energy deregulation or re-regulation, health care reform and financial reform;

•

timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment, including, without limitation, the outcome of the application to change rates submitted to the Public Utility Commission of Texas by CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) in June 2010;

•

the timing and outcome of any audits, disputes and other proceedings related to taxes;

•

problems with construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;

•

industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures, and demographic patterns;

•

the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids;

•

the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business and transporting by our interstate pipelines;

•

the timing and extent of changes in natural gas basis differentials;

•

weather variations and other natural phenomena;

•

the impact of unplanned facility outages;

•

timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;

•

changes in interest rates or rates of inflation;

•

commercial bank and financial market conditions, our access to capital, the cost of such capital, and the

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results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

•

actions by rating agencies;

•

effectiveness of our risk management activities;

•

inability of various counterparties to meet their obligations to us;

•

non-payment for our services due to financial distress of our customers;

•

the ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

•

the ability of retail electric providers, and particularly the two largest customers of CenterPoint Houston, which are subsidiaries of NRG Retail LLC and TXU Energy Retail Company LLC, to satisfy their obligations to us and our subsidiaries;

•

the outcome of litigation brought by or against us;

•

our ability to control costs;

•

the investment performance of our pension and postretirement benefit plans;

•

our potential business strategies, including restructurings, acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;

•

acquisition and merger activities involving us or our competitors; and

•

other factors we discuss in “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q and other reports we file from time to time with the Securities and Exchange Commission.

You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement.

iii

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(In Millions, Except Per Share Amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2010			2009			2010

Revenues	$	1,640		$	1,756		$	4,406		$	4,779

Expenses:
Natural gas		710			778			2,499			2,713
Operation and maintenance		398			410			811			824
Depreciation and amortization		188			217			354			417
Taxes other than income taxes		91			88			204			205
Total		1,387			1,493			3,868			4,159
Operating Income		253			263			538			620

Other Income (Expense):
Gain (loss) on marketable securities		55			(22	)		21			16
Gain (loss) on indexed debt securities		(46	)		32			(24	)		5
Interest and other finance charges		(129	)		(121	)		(258	)		(243	)
Interest on transition and system restoration bonds		(33	)		(36	)		(66	)		(72	)
Equity in earnings of unconsolidated affiliates		11			7			11			12
Other, net		18			3			22			4
Total		(124	)		(137	)		(294	)		(278	)

Income Before Income Taxes		129			126			244			342
Income tax expense		(43	)		(45	)		(91	)		(147	)
Net Income	$	86		$	81		$	153		$	195

Basic Earnings Per Share	$	0.24		$	0.20		$	0.44		$	0.49

Diluted Earnings Per Share	$	0.24		$	0.20		$	0.44		$	0.49

Dividends Declared Per Share	$	0.19		$	0.195		$	0.38		$	0.39

Weighted Average Shares Outstanding, Basic		352			400			347			396

Weighted Average Shares Outstanding, Diluted		354			402			349			399

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

ASSETS

	December 31, 2009		June 30, 2010
Current Assets:
Cash and cash equivalents ($163 related to VIEs at June 30, 2010)	$	740	$	583
Investment in marketable securities		300		316
Accounts receivable, net ($70 related to VIEs at June 30, 2010)		790		716
Accrued unbilled revenues		485		169
Natural gas inventory		189		146
Materials and supplies		138		157
Non-trading derivative assets		39		46
Prepaid expenses and other current assets ($33 related to VIEs at June 30, 2010)		223		219
Total current assets		2,904		2,352

Property, Plant and Equipment:
Property, plant and equipment		14,770		15,382
Less accumulated depreciation and amortization		3,982		4,165
Property, plant and equipment, net		10,788		11,217

Other Assets:
Goodwill		1,696		1,696
Regulatory assets ($2,752 related to VIEs at June 30, 2010)		3,677		3,540
Non-trading derivative assets		15		17
Investment in unconsolidated affiliates		463		479
Other		230		220
Total other assets		6,081		5,952

Total Assets	$	19,773	$	19,521

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

(In Millions)

(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

	December 31, 2009			June 30, 2010
Current Liabilities:
Short-term borrowings	$	55		$	32
Current portion of VIE transition and system restoration bonds long-term debt		241			274
Current portion of indexed debt		121			124
Current portion of other long-term debt		541			769
Indexed debt securities derivative		201			196
Accounts payable		648			418
Taxes accrued		148			130
Interest accrued		181			193
Non-trading derivative liabilities		51			63
Accumulated deferred income taxes, net		406			383
Other		445			450
Total current liabilities		3,038			3,032

Other Liabilities:
Accumulated deferred income taxes, net		2,776			2,773
Unamortized investment tax credits		16			13
Non-trading derivative liabilities		42			30
Benefit obligations		861			861
Regulatory liabilities		921			967
Other		361			374
Total other liabilities		4,977			5,018

Long-term Debt:
VIE transition and system restoration bonds		2,805			2,665
Other		6,314			5,745
Total long-term debt		9,119			8,410

Commitments and Contingencies (Note 11)

Shareholders’ Equity:
Common stock (391,746,779 shares and 421,476,056 shares outstanding at December 31, 2009 and June 30, 2010, respectively)		4			4
Additional paid-in capital		3,671			4,047
Accumulated deficit		(912	)		(871	)
Accumulated other comprehensive loss		(124	)		(119	)
Total shareholders’ equity		2,639			3,061

Total Liabilities and Shareholders’ Equity	$	19,773		$	19,521

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In Millions)

(Unaudited)

	Six Months Ended June 30,
	2009			2010
Cash Flows from Operating Activities:
Net income	$	153		$	195
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		354			417
Amortization of deferred financing costs		20			14
Deferred income taxes		78			(37	)
Unrealized loss (gain) on marketable securities		(21	)		(16	)
Unrealized loss (gain) on indexed debt securities		24			(5	)
Write-down of natural gas inventory		6			—
Equity in earnings of unconsolidated affiliates, net of distributions		(8	)		6
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		641			355
Inventory		332			24
Accounts payable		(502	)		(215	)
Fuel cost over (under) recovery		(34	)		93
Non-trading derivatives, net		18			1
Margin deposits, net		39			(18	)
Interest and taxes accrued		(70	)		(7	)
Net regulatory assets and liabilities		19			26
Other current assets		13			21
Other current liabilities		(29	)		(32	)
Other assets		(1	)		(9	)
Other liabilities		20			(3	)
Other, net		4			8
Net cash provided by operating activities		1,056			818

Cash Flows from Investing Activities:
Capital expenditures		(504	)		(727	)
Decrease in restricted cash of transition and system restoration bonds companies		6			1
Investment in unconsolidated affiliates		1			(22	)
Cash received from DOE grant		—			33
Other, net		(7	)		(4	)
Net cash used in investing activities		(504	)		(719	)

Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(78	)		(23	)
Revolving credit facilities, net		(932	)		—
Proceeds from long-term debt		500			—
Payments of long-term debt		(110	)		(448	)
Debt issuance costs		(4	)		(2	)
Payment of common stock dividends		(133	)		(154	)
Proceeds from issuance of common stock, net		188			370
Other, net		1			1
Net cash used in financing activities		(568	)		(256	)

Net Decrease in Cash and Cash Equivalents		(16	)		(157	)
Cash and Cash Equivalents at Beginning of Period		167			740
Cash and Cash Equivalents at End of Period	$	151		$	583

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	298		$	292
Income taxes, net		55			144
Non-cash transactions:
Accounts payable related to capital expenditures		64			99

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)	Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2009 (CenterPoint Energy Form 10-K).

Background. CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of June 30, 2010, CenterPoint Energy’s indirect wholly owned subsidiaries included:

•

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes the city of Houston; and

•

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems in six states. Subsidiaries of CERC Corp. own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

CenterPoint Energy’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in CenterPoint Energy’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of CenterPoint Energy’s reportable business segments, reference is made to Note 15.

(2)	New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (FASB) issued new accounting guidance on consolidation of variable interest entities (VIEs) that changes how a reporting entity determines a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards approach to a qualitative approach based on which variable interest holder has the power to direct the economic performance related activities of the VIE as well as the obligation to absorb losses or right to receive benefits that could potentially be significant to the VIE. This new guidance requires the primary beneficiary assessment to be performed on an ongoing basis and also requires enhanced disclos ures that will provide more transparency about a company’s involvement in a VIE. This new guidance was effective for a reporting entity’s first annual reporting period beginning after November 15, 2009. CenterPoint Energy’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. As of June 30, 2010, CenterPoint Energy has four VIEs related to transition and system restoration bond companies (see Note 4) which it consolidates. The consolidated VIEs are wholly-owned bankruptcy remote special purpose entities that were formed specifically for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy have no recourse to any assets or revenues

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of the transition and system restoration bond companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property and the bond holders have no recourse to the general credit of CenterPoint Energy.

In January 2010, the FASB issued new accounting guidance to require additional fair value related disclosures including transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosure guidance about the level of disaggregation and about inputs and valuation techniques. This new guidance was effective for the first reporting period beginning after December 15, 2009 except for the requirement to separately disclose purchases, sales, issuances and settlements relating to Level 3 measurements, which is effective for the first reporting period beginning a fter December 15, 2010. CenterPoint Energy's adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 6 for the required disclosures. CenterPoint Energy expects that the adoption of the Level 3 related gross disclosure requirement, which is effective in 2011, will not have a material impact on its financial position, results of operations or cash flows.

Management believes the impact of other recently issued standards, which are not yet effective, will not have a material impact on CenterPoint Energy’s consolidated financial position, results of operations or cash flows upon adoption.

(3)	Employee Benefit Plans

CenterPoint Energy’s net periodic cost includes the following components relating to pension and postretirement benefits:

	Three Months Ended June 30,
	2009						2010
	Pension Benefits (1)			Postretirement Benefits			Pension Benefits (1)			Postretirement Benefits
	(in millions)
Service cost	$	6		$	1		$	8		$	1
Interest cost		29			7			26			6
Expected return on plan assets		(25	)		(3	)		(28	)		(3	)
Amortization of prior service credit		1			1			1			1
Amortization of net loss		17			—			14			—
Amortization of transition obligation		—			1			—			1
Net periodic cost	$	28		$	7		$	21		$	6

	Six Months Ended June 30,
	2009						2010
	Pension Benefits (1)			Postretirement Benefits			Pension Benefits (1)			Postretirement Benefits
	(in millions)
Service cost	$	12		$	1		$	16		$	1
Interest cost		57			14			51			12
Expected return on plan assets		(49	)		(5	)		(55	)		(5	)
Amortization of prior service credit		2			2			2			2
Amortization of net loss		34			—			29			—
Amortization of transition obligation		—			3			—			3
Net periodic cost	$	56		$	15		$	43		$	13

_________

(1)

Net periodic cost in these tables is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes. CenterPoint Houston’s actuarially determined pension expense for 2010 in excess of the 2007 base year amount is being deferred for rate making purposes until its next general rate case pursuant to Texas law. CenterPoint Houston deferred as a regulatory asset $9 million and $6 million, respectively, in pension expense during the three months ended June 30, 2009 and 2010, and $13 million and $12 million, respectively, in pension expense during the six months ended June 30, 2009 and 2010.

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CenterPoint Energy expects to contribute approximately $9 million to its pension plans in 2010, of which approximately $2 million and $5 million, respectively, was contributed during the three and six months ended June 30, 2010.

CenterPoint Energy expects to contribute approximately $19 million to its postretirement benefits plan in 2010, of which approximately $6 million and $13 million, respectively, was contributed during the three and six months ended June 30, 2010.

(4)	Regulatory Matters

(a) Recovery of True-Up Balance

In March 2004, CenterPoint Houston filed its true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and certain other adjustments.

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:

•

reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

•

reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers (REPs); and

•

affirmed the True-Up Order in all other respects.

The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

•

reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

•

reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.);

•

ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

•

affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

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assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances wi thout proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true-up award.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision. Oral argument before the court was held in October 2009, and the parties have filed post-submission briefs to the court. Although CenterPoint Energy and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its appeal to the Texas Supreme Court, CenterPoint Energy can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, CenterPoint Energy recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in CenterPoint Energy’s consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, CenterPoint Energy anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-Up Order, but could range from $180 million to $410 million (pre-tax) plus interest subsequent to December 31, 2009.

In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. CenterPoint Energy believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 that would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and, in March 20 08, adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, CenterPoint Energy received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require CenterPoint Energy to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on CenterPoint Energy’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. CenterPoint Energy and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

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The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005, a new special purpose subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.

In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on REPs to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston ’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Ho uston to recover through Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two parties appealed the court of appeals decision to the Texas Supreme Court which heard oral argument in October 2009. The ultimate outcome of this matter cannot be predicted at this time. However, CenterPoint Energy does not expect the disposition of this matter to have a material adverse effect on CenterPoint Energy’s or CenterPoint Houston’s fi nancial condition, results of operations or cash flows.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, pursuant to the financing order, a new special purpose subsidiary of CenterPoint Houston issued appro ximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

As of June 30, 2010, CenterPoint Energy has not recognized an allowed equity return of $186 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates. During both the three months ended June 30, 2009 and 2010, CenterPoint Houston recognized approximately $4 million of the allowed equity return not previously recognized. During the six months ended June 30, 2009 and 2010, CenterPoint Houston recognized approximately $6 million and $7 million, respectively, of the allowed equity return not previously recognized.

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(b) Rate Proceedings

Texas - June 2010 Rate Filing. As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Texas Utility Commission and the cities in its service area, including cost data and other information that support a retail base rate increase of at least $76 million for delivery charges to the REPs that sell electricity to end-use customers in CenterPoint Houston’s service territory. The rate filing package also supports an increase of $18 million for wholesale transmission customers.

In the filing, CenterPoint Houston is also requesting to reconcile its current Advanced Metering System (AMS) costs incurred as of March 31, 2010, and to revise the estimated costs to complete the AMS project to reflect $150 million in funds from the $200 million Department of Energy (DOE) stimulus grant awarded to CenterPoint Houston and updated cost information. The reconciliation plan also requests that the duration of the residential AMS surcharge be shortened by six years from the original 12-year plan.

In its filing, CenterPoint Houston proposed that the Texas Utility Commission approve an alternative ratemaking mechanism that would allow for the adjustment of rates to reflect changes in certain costs and consumer usage on an annual basis. In an interim order in the rate proceeding, the Texas Utility Commission ruled that that proposal should instead be considered in its now-pending rulemaking regarding alternative ratemaking and will not be addressed in the rate proceeding.

CenterPoint Houston’s filing seeks a return on equity of 11.25% and proposes that rates be based on a capital structure of 50% equity and 50% long-term debt.

Based on the statutory timeline prescribed for action on rate case filings, CenterPoint Energy expects that a decision could be rendered by the Texas Utility Commission as early as late 2010.

Texas - Other. In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain estimated 2010 energy efficiency program costs, an energy efficiency performance bonus for 2008 programs, and carrying costs totaling approximately $10 million. The application sought to begin recovery of these costs through a surcharge effective July 1, 2010. In October 2009, the Texas Utility Commission issued its order approving recovery of the 2010 energy efficiency program costs and a partial performance bonus, plus carrying costs, but refused to permit CenterPoint Houston to recover a performance bonus of $2 million on approximately $10 million in 2008 energy efficiency costs expended pursuant to the terms of a settlemen t agreement reached in CenterPoint Houston’s 2006 rate proceeding. CenterPoint Houston has appealed the denial of the full 2008 performance bonus to the 98th district court in Travis County, Texas, where the case remains pending. CenterPoint Houston began collecting the approved amounts in July 2010.

In April 2010, CenterPoint Houston filed an application with the Texas Utility Commission to recover a total of approximately $14.4 million in costs related to its energy efficiency programs. The filing seeks authorization to recover certain projected costs for its 2011 energy efficiency programs, an energy efficiency performance bonus for 2009 programs, and revenue losses related to the implementation of the 2009 energy efficiency program. The application seeks to begin recovery of these costs through a surcharge beginning in January 2011. In preliminary orders in this proceeding, the Texas Utility Commission has excluded approximately $2.1 million of the requested performance bonus for the 2009 programs and has concluded that it does not have the statutory authority to permit recovery of the requested $1.4 million of lost revenues associated with the 2009 programs. A final order is not expected until later this year.

In March 2008, the natural gas distribution business of CERC (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, the Railroad Commission approved the implementation of rates increasing annual revenues by approximately $3.5 million. The implemented rates were contested by a coalition of nine cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. In its final judgment, the court ruled that the Railroad Commission lacked authority to impose the approved cost of service adjustment mechanism in both those nine cities and in those areas in which the Railroad Commission has original jurisdiction. The Railroad Commission and Gas

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Operations have appealed the court’s ruling on the cost of service adjustment mechanism to the 3rd Court of Appeals at Austin, Texas. CenterPoint Energy and CERC do not expect the outcome of this matter to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs of approximately $2 million on its gas inventory. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the co urt’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates as well as adjustments to pension and benefits, accumulated deferred income taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years. These rates went into effect in March 2010. Gas Operations and other parties are seeking judicial review of the Railroad Commission’s decision in the 261st district court in Travis County, Texas.

Minnesota. In November 2008, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. In January 2010, the MPUC issued its decision authorizing a revenue increase of $40.8 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In July 2010, Gas Operations implemented the revised rates approved by the MPUC. The difference between the amounts approved by the MPUC and amounts collected, $15.9 million as of June 30, 2010, is recorded in other current liabilities and will be refunded to customers in 2010.

(5)	Derivative Instruments

CenterPoint Energy is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on its operating results and cash flows. Such derivatives are recognized in CenterPoint Energy’s Condensed Consolidated Balance Sheets at their fair value unless CenterPoint Energy elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and business segment officers that oversees all commodity price, weather and credit risk activities, including CenterPoint Energy’s marketing, risk management services and hedging activities. The committee’s duties are to establish CenterPoint Energy’s commodity risk policies, allocate board-approved commercial risk limits, approve use of new products and commodities, monitor positions and ensure compliance with CenterPoint Energy’s risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.

CenterPoint Energy’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

(a) Non-Trading Activities

Derivative Instruments. CenterPoint Energy enters into certain derivative instruments to manage physical commodity price risks but does not engage in proprietary or speculative commodity trading. CenterPoint Energy has not elected to designate these instruments as cash flow or fair value hedges.

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During the three months ended June 30, 2009, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $37 million and decreased natural gas expense from unrealized net gains of $40 million, resulting in a net unrealized gain of $3 million. During the three months ended June 30, 2010, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $13 million and decreased natural gas expense from unrealized net gains of $5 million, resulting in a net unrealized loss of $8 million. During the six months ended June 30, 2009, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $34 million and decreased natural gas expense from unrealized net gains of $18 million, resulting in a net unrealized loss of $16 million. During the six months ended June 30, 2010, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $17 million and increased natural gas expense from unrealized net losses of $22 million, resulting in a net unrealized loss of $5 million.

Weather Hedges. CenterPoint Energy has weather normalization or other rate mechanisms that mitigate the impact of weather on its gas operations in Arkansas, Louisiana, Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of the gas operations in the remaining jurisdictions and in CenterPoint Houston’s service territory.

CenterPoint Energy enters into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. The swaps were based on ten-year normal weather. During the three and six months ended June 30, 2009, CenterPoint Energy recognized losses of $-0- and $3 million, respectively, related to these swaps. During the three and six months ended June 30, 2010, CenterPoint Energy recognized gains of $2 million and losses of $5 million, respectively, related to these swaps. The losses were substantially offset by increased revenues due to colder than normal weather. Weather hedge losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CenterPoint Energy’s derivative instruments and hedging activities. The first tables provide a balance sheet overview of CenterPoint Energy’s Derivative Assets and Liabilities as of December 31, 2009 and June 30, 2010, while the latter tables provide a breakdown of the related income statement impact for the three and six months ended June 30, 2009 and 2010.

Fair Value of Derivative Instruments
	December 31, 2009
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	46	$	(7	)
Natural gas contracts (1)	Other Assets		16		(1	)
Natural gas contracts (1)	Current Liabilities		20		(123	)
Natural gas contracts (1)	Other Liabilities		1		(86	)
Indexed debt securities derivative	Current Liabilities		—		(201	)
Total		$	83	$	(418	)

_________

(1)

Natural gas contracts are subject to master netting arrangements and are presented on a net basis in the Condensed Consolidated Balance Sheets. This netting causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets.

(2)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 674 billion cubic feet (Bcf) or a net 152 Bcf long position. Of the net long position, basis swaps constitute 71 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 51 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $39 million liability as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $95 million.

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Fair Value of Derivative Instruments
	June 30, 2010
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	48	$	(2	)
Natural gas contracts (1)	Other Assets		17		—
Natural gas contracts (1)	Current Liabilities		17		(156	)
Natural gas contracts (1)	Other Liabilities		1		(67	)
Indexed debt securities derivative	Current Liabilities		—		(196	)
Total		$	83	$	(421	)

_________

(1)

(2)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 741 Bcf or a net 158 Bcf long position. Of the net long position, basis swaps constitute 86 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 40 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $30 million liability as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $112 million.

For CenterPoint Energy’s price stabilization activities of the Natural Gas Distribution business segment, the settled costs of derivatives are ultimately recovered through purchased gas adjustments. Accordingly, the net unrealized gains and losses associated with these contracts are recorded as net regulatory assets. Realized and unrealized gains and losses on other derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for natural gas derivatives and non-retail related physical gas derivatives. Unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) in the Condensed Statements of Consolidated Income.

Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2009			2010
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	7		$	5
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(43	)		(31	)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)		(46	)		32
Total		$	(82	)	$	6

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(39) million and $(25) million of costs in 2009 and 2010, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered/refunded through purchased gas adjustments.

Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2009			2010
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	84		$	49
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(192	)		(92	)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)		(24	)		5
Total		$	(132	)	$	(38	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(117) million and $(50) million of costs in 2009 and 2010, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered/refunded through purchased gas adjustments.

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CenterPoint Energy enters into financial derivative contracts containing material adverse change provisions. These provisions require CenterPoint Energy to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit ratings of CenterPoint Energy, Inc. or its subsidiaries are downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at December 31, 2009 and June 30, 2010 was $140 million and $144 million, respectively. The aggregate fair value of assets that are already posted as collateral was $65 million and $59 million, respectively, at December 31, 2009 and June 30, 2010. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2009 and June 30, 2010, $75 million and $84 million, respectively, of additional assets would be required to be posted as collateral.

(6)	Fair Value Measurements

Assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in this guidance and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are financial derivatives, investments and equity securities listed in active markets.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value CenterPoint Energy’s Level 2 assets or liabilities.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. Unobservable inputs reflect CenterPoint Energy’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CenterPoint Energy develops these inputs based on the best information available, including CenterPoint Energy’s own data. A market approach is ut ilized to value CenterPoint Energy’s Level 3 assets or liabilities.

CenterPoint Energy determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period. For the quarter ended June 30, 2010, there were no significant transfers between levels.

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The following tables present information about CenterPoint Energy’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2009 and June 30, 2010, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energy to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2009
	(in millions)
Assets
Corporate equities	$	301	$	—	$	—	$	—		$	301
Investments in money market funds		41		—		—		—			41
Natural gas derivatives		1		77		5		(29	)		54
Total assets	$	343	$	77	$	5	$	(29	)	$	396
Liabilities
Indexed debt securities derivative	$	—	$	201	$	—	$	—		$	201
Natural gas derivatives		12		194		11		(124	)		93
Total liabilities	$	12	$	395	$	11	$	(124	)	$	294

_________

(1)

Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $95 million posted with the same counterparties.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of June 30, 2010
	(in millions)
Assets
Corporate equities	$	318	$	—	$	—	$	—		$	318
Investments in money market funds		42		—		—		—			42
Natural gas derivatives		1		75		7		(20	)		63
Total assets	$	361	$	75	$	7	$	(20	)	$	423
Liabilities
Indexed debt securities derivative	$	—	$	196	$	—	$	—		$	196
Natural gas derivatives		13		210		2		(132	)		93
Total liabilities	$	13	$	406	$	2	$	(132	)	$	289

_________

(1)

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The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy has utilized Level 3 inputs to determine fair value:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended June 30,
	2009			2010
	(in millions)
Beginning balance	$	(26	)	$	4
Total unrealized gains or (losses):
Included in earnings		1			—
Included in regulatory assets		1			—
Total purchases, sales, other settlements, net:
Included in earnings		—			1
Included in regulatory assets		7			—
Ending balance	$	(17	)	$	5
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	1		$	1

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Six Months Ended June 30,
	2009			2010
	(in millions)
Beginning balance	$	(58	)	$	(6	)
Total unrealized gains or (losses):
Included in earnings		(2	)		2
Included in regulatory assets		(16	)		(1	)
Total purchases, sales, other settlements, net:
Included in earnings		2			1
Included in regulatory assets		57			9
Ending balance	$	(17	)	$	5
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	(1	)	$	3

(7)

Goodwill

Goodwill by reportable business segment as of both December 31, 2009 and June 30, 2010 is as follows (in millions):

Natural Gas Distribution	$	746
Interstate Pipelines		579
Competitive Natural Gas Sales and Services		335
Field Services		25
Other Operations		11
Total	$	1,696

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(8)	Comprehensive Income

The following table summarizes the components of total comprehensive income (net of tax):

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2009		2010		2009		2010
	(in millions)
Net income	$	86	$	81	$	153	$	195
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $1, $1, $3 and $3)		4		2		6		5
Total		4		2		6		5
Comprehensive income	$	90	$	83	$	159	$	200

The following table summarizes the components of accumulated other comprehensive loss:

	December 31, 2009			June 30, 2010
	(in millions)
Adjustment related to pension and postretirement plans	$	(120	)	$	(115	)
Net deferred loss from cash flow hedges		(4	)		(4	)
Total accumulated other comprehensive loss	$	(124	)	$	(119	)

(9)	Capital Stock

CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2009, 391,746,945 shares of CenterPoint Energy common stock were issued and 391,746,779 shares were outstanding. At June 30, 2010, 421,476,222 shares of CenterPoint Energy common stock were issued and 421,476,056 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2009 and June 30, 2010.

During the six months ended June 30, 2010, CenterPoint Energy received proceeds of approximately $42 million from the sale of approximately 3.1 million shares of common stock to its defined contribution plan and proceeds of approximately $7 million from the sale of approximately 0.5 million shares of common stock to participants in its enhanced dividend reinvestment plan.

In June 2010, CenterPoint Energy issued 25.3 million shares of its common stock at a price to the public of $12.90 per share. CenterPoint Energy received net proceeds from the offering of approximately $315 million, after deducting underwriting discounts and offering expenses.

(10)	Short-term Borrowings and Long-term Debt

(a) Short-term Borrowings

Receivables Facility. On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. As of December 31, 2009 and June 30, 2010, the facility size was $150 million and $300 million, respectively. As of both December 31, 2009 and June 30, 2010, there were no advances under the receivables facility.

Inventory Financing. In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma. Pursuant to the provisions of the agreements, Gas Operations sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a financing and they had an associated principal obligation of $55 million and $32 million as of December 31, 2009 and June 30, 2010, respectively.

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Also in October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in south Louisiana, Mississippi and Texas. In connection with these asset management agreements, Gas Operations exchanged natural gas in storage for the right to receive an equivalent amount of natural gas during the 2009-2010 winter heating season. Although title to the natural gas in storage at inception of the contract was transferred to the third party, the natural gas continued to be accounted for as inventory due to the right to receive an equivalent amount of natural gas during the winter heating season. As of December 31, 2009 and June 30, 2010, CenterPoint Energy’s Condensed Consolidated Balance Sheets reflect $10 million and $-0-, respectively, in inventory related to these agreements .

(b) Long-term Debt

Pollution Control Bonds. In January 2010, CenterPoint Energy purchased $290 million principal amount of pollution control bonds issued on its behalf at 101% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. Prior to the purchase, the pollution control bonds had a fixed rate of interest of 5.125%.

Convertible Subordinated Debentures. In January 2010, CERC Corp. redeemed $45 million of its outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Revolving Credit Facilities. As of both December 31, 2009 and June 30, 2010, there were no outstanding borrowings under CenterPoint Energy’s, CenterPoint Houston’s or CERC Corp.’s long-term revolving credit facilities.

As of December 31, 2009 and June 30, 2010, CenterPoint Energy had approximately $25 million and $20 million, respectively, of outstanding letters of credit under its $1.2 billion credit facility. As of both December 31, 2009 and June 30, 2010 CenterPoint Houston had approximately $4 million of outstanding letters of credit under its $289 million credit facility. There was no commercial paper outstanding that would have been backstopped by CenterPoint Energy’s $1.2 billion credit facility or by CERC Corp.'s credit facility as of December 31, 2009 and June 30, 2010. CenterPoint Energy, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of June 30, 2010.

CenterPoint Energy’s $1.2 billion credit facility has a first drawn cost of the London Interbank Offered Rate (LIBOR) plus 55 basis points based on CenterPoint Energy’s current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant (as those terms are defined in the facility). In February 2010, CenterPoint Energy amended its credit facility to modify the covenant to allow for a temporary increase of the permitted ratio from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a calendar year, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial ratio covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

CenterPoint Houston’s $289 million credit facility contains a debt (excluding transition and system restoration bonds) to total capitalization covenant. The facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings.

CERC Corp.’s $915 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

Under CenterPoint Energy’s $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and CERC Corp.’s $915 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit rating.

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(11)	Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s Consolidated Balance Sheets as of December 31, 2009 and June 30, 2010 as these contracts meet the exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of June 30, 2010, minimum payment obligations for natural gas supply commitments are approximately $262 million for the remaining six months in 2010, $501 million in 2011, $407 million in 2012, $346 million in 2013, $255 million in 2014 and $579 million after 2014.

(b) Capital Commitments

Long-Term Gas Gathering and Treating Agreements. In September 2009, CenterPoint Energy Field Services, Inc. (CEFS) entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from Encana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production. The gatherin g facilities are known as the “Magnolia Gathering System.”

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place the majority of those facilities in service in the third quarter of 2010 with well connects being the only activity remaining. CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. As of June 30, 2010, approximately $286 million has been spent on the original project scope, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat a total volume of up to 1 Bcf per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be approximately $60 million, and the increased capacity is expected to be in service by the first quarter of 2011. In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

If Encana and Shell elect expansion of the project to gather and treat additional future volumes of up to 1 Bcf per day (including the 200 MMcf per day already elected), CEFS estimates that the expansion would cost as much as $300 million, and Encana and Shell would provide incremental volume commitments.

In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to the agreements, CEFS has also acquired existing jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in De Soto and Red River parishes in northwest Louisiana.

CEFS has integrated the acquired facilities with CEFS’s Magnolia Gathering System, allowing CEFS to commence gathering and treating services immediately for up to 150 MMcf per day of natural gas. Under the terms of the agreements, CEFS will expand the acquired facilities to gather and treat up to 600 MMcf per day of natural gas. Each of the agreements includes volume commitments and dedicated acreage for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

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CEFS will expand the project to gather and treat additional future volumes of up to 520 MMcf per day, for a total Olympia Gathering System capacity of up to 1.1 Bcf per day. CEFS estimates that the incremental expansion to 1.1 Bcf per day would cost as much as an additional $200 million. Encana and Shell would provide incremental volume commitments in connection with expansions of the Olympia Gathering System.

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits. Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alle ging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but in March 2010 the plaintiffs appealed the dismissal to the Nevada Supreme Court. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases. CenterPoint Energy does not expect the ultimate outcome of these remaining matters to have a material impact on its financial condition, results of operations or cash flows.

In May 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. and no longer provides service as a REP in CenterPoint Houston’s service territory. In April 2010, RRI announced its plan to merge with Mirant Corporation in an all-stock transaction. Neither the sale of the retail business nor the merger with Mirant Corporation, if ultimately finalized, alters RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts discussed below under Gua ranties.

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment, the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. su bsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case and, in March 2010, denied the plaintiffs’ request for reconsideration of that order.

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CERC believes that there has been no systematic mismeasurement of gas and that these lawsuits are without merit. CERC and CenterPoint Energy do not expect the ultimate outcome of the lawsuits to have a material impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Environmental Matters

Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGPs) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC’s Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.

At June 30, 2010, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechani sm and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers in 2010. As of June 30, 2010, the amount to be refunded from the environmental expense tracker account was $8.3 million. The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. CERC was not required to refund to customers the amount collected from insurance companies, $5.0 million at June 30, 2010, to be used to mitigate future environmental costs. The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures. This provision had no impact on earnings.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing would be required to determine if other p otentially responsible parties, including CERC, would have to contribute to that remediation. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. CERC believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP. CERC and CenterPoint Energy do not expect the ultimate outcome to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Mercury Contamination. CenterPoint Energy’s pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. CenterPoint Energy has found this type of contamination at some sites in the past, and CenterPoint Energy has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs is not known at this time, based on CenterPoint Energy’s experience and that of others in th e natural gas industry to date and on the current regulations regarding remediation of these sites, CenterPoint Energy believes that the costs of any remediation of these sites will not be material to CenterPoint Energy’s financial condition, results of operations or cash flows.

Asbestos. Some facilities owned by CenterPoint Energy contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy or its subsidiaries have been named, along with numerous others,

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as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by CenterPoint Energy, but most existing claims relate to facilities previously owned by CenterPoint Energy’s subsidiaries. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. In 2004, CenterPoint Energy sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but CenterPoint Energy has agreed to continue to defend such claims to the extent they are c overed by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from NRG Texas LP. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC and the plaintiffs reache d agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CenterPoint Energy and CERC do not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Other Environmental. From time to time CenterPoint Energy has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CenterPoint Energy has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CenterPoint Energy does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

Other Proceedings

CenterPoint Energy is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. CenterPoint Energy regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. CenterPoint Energy does not expect the disposition of these matters to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

(d) Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be in effect until 2018, w as approximately $89 million as of June 30, 2010. As of June 30, 2010, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

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(12)	Income Taxes

During the three and six months ended June 30, 2009, the effective tax rate was 33% and 37%, respectively. During the three and six months ended June 30, 2010, the effective tax rate was 36% and 43%, respectively. The most significant item affecting the comparability of the effective tax rate for the three months ended June 30, 2009 and 2010 is a tax settlement with RRI that occurred on June 30, 2009. The comparability of the effective tax rate for the six months ended June 30, 2009 and 2010 is primarily affected by a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs which are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, CenterPoint Energy reduced its deferred tax asset by approximately $32 million in March 2010. The portion of the reduction that CenterPoint Energy believes will be recovered through the regulatory process, or approximately $11 million, has been recorded as an adjustment to regulatory assets. The remaining $21 million of the reduction in CenterPoint Energy’s deferred tax asset has been reflected as a charge to income tax expense.

The following table summarizes CenterPoint Energy’s unrecognized tax benefits at December 31, 2009 and June 30, 2010:

	December 31, 2009		June 30, 2010
	(in millions)
Unrecognized tax benefits	$	187	$	196
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate		10		12
Interest accrued on unrecognized tax benefits		3		8

It is reasonably possible that the total amount of unrecognized tax benefits could decrease by as much as $61 million or increase by as much as $82 million over the next 12 months primarily as a result of the tax normalization issue described in Note 4(a), a temporary difference, and the anticipated resolution of CenterPoint Energy’s administrative appeal associated with an IRS examination described in the following paragraph.

On July 1, 2010, the IRS issued a report outlining proposed adjustments with respect to its examination of CenterPoint Energy’s 2006 and 2007 federal income tax returns. The most significant adjustment proposed by the IRS relates to the disallowance of CenterPoint Energy’s casualty loss deduction totaling $603 million associated with the damage caused by Hurricane Ike. Pursuant to an election made by CenterPoint Energy, the casualty loss deduction was taken in the taxable year preceding the taxable year in which the hurricane occurred. CenterPoint Energy has filed an administrative appeal with the IRS Appeals Office and intends to vigorously defend its reporting of the casualty loss. CenterPoint Energy has considered the effects of the proposed disallowance of the casualty l oss deduction by the IRS in its accrual for uncertain income tax positions as of June 30, 2010. Additionally, the casualty loss deduction is a temporary difference and therefore, any increase or decrease in the balance of unrecognized tax benefits related thereto would not affect the effective tax rate.

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(13)	Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as "available-for-sale" and "trading" and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities and CenterPoint Energy’s 2.00% Zero-Premium Exchangeable Subordinated Notes due 2029 indexed debt securities derivative are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price.

	December 31, 2009				June 30, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	9,900	$	10,413	$	9,453	$	10,296

(14)	Earnings Per Share

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per share calculations:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Net income	$	86	$	81	$	153	$	195

Weighted average shares outstanding		352,461,000		399,515,000		346,660,000		396,203,000

Basic earnings per share:
Net income	$	0.24	$	0.20	$	0.44	$	0.49

Diluted earnings per share calculation:
Net income	$	86	$	81	$	153	$	195

Weighted average shares outstanding		352,461,000		399,515,000		346,660,000		396,203,000
Plus: Incremental shares from assumed conversions:
Stock options (1)		396,000		560,000		439,000		568,000
Restricted stock		1,423,000		1,918,000		1,423,000		1,918,000
Weighted average shares assuming dilution		354,280,000		401,993,000		348,522,000		398,689,000

Diluted earnings per share:
Net income	$	0.24	$	0.20	$	0.44	$	0.49

_________

(1)

Options to purchase 3,528,676 shares and 2,590,400 shares were outstanding for the three and six months ended June 30, 2009, respectively, and options to purchase 1,616,951 shares were outstanding for both the three and six months ended June 30, 2010, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.

(15)	Reportable Business Segments

CenterPoint Energy’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in the CenterPoint Energy Form 10-K. CenterPoint Energy uses operating income as the measure of profit or loss for its business segments.

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CenterPoint Energy’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents CenterPoint Energy’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. The Interstate Pipelines busine ss segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the non-rate regulated natural gas gathering, processing and treating operations. Other Operations consists primarily of other corporate operations which support all of CenterPoint Energy’s business operations.

Financial data for business segments are as follows (in millions):

	For the Three Months Ended June 30, 2009
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	521	(1)	$	—		$	162
Natural Gas Distribution		516			2			2
Competitive Natural Gas Sales and Services		430			2			6
Interstate Pipelines		119			36			61
Field Services		51			5			23
Other Operations		3			—			(1	)
Eliminations		—			(45	)		—
Consolidated	$	1,640		$	—		$	253

	For the Three Months Ended June 30, 2010
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	562	(1)	$	—		$	158
Natural Gas Distribution		462			3			10
Competitive Natural Gas Sales and Services		550			10			(6	)
Interstate Pipelines		113			35			67
Field Services		66			14			31
Other Operations		3			—			3
Eliminations		—			(62	)		—
Consolidated	$	1,756		$	—		$	263

	For the Six Months Ended June 30, 2009
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2009
Electric Transmission & Distribution	$	933	(1)	$	—		$	232		$	9,755
Natural Gas Distribution		1,934			5			120			4,535
Competitive Natural Gas Sales and Services		1,190			7			8			1,176
Interstate Pipelines		236			72			130			3,484
Field Services		107			6			49			1,045
Other Operations		6			—			(1	)		2,261	(2)
Eliminations		—			(90	)		—			(2,483	)
Consolidated	$	4,406		$	—		$	538		$	19,773

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	For the Six Months Ended June 30, 2010
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of June 30, 2010
Electric Transmission & Distribution	$	1,044	(1)	$	—		$	265	$	9,711
Natural Gas Distribution		1,995			7			149		4,463
Competitive Natural Gas Sales and Services		1,394			18			9		1,147
Interstate Pipelines		216			70			139		3,568
Field Services		124			24			54		1,428
Other Operations		6			—			4		1,982	(2)
Eliminations		—			(119	)		—		(2,778	)
Consolidated	$	4,779		$	—		$	620	$	19,521

_________

(1)

Sales to subsidiaries of NRG Retail LLC, the successor to RRI's Texas retail business, in the three months ended June 30, 2009 and 2010 represented approximately $151 million and $132 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of TXU Energy Retail Company LLC in both the three months ended June 30, 2009 and 2010 represented approximately $42 million of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of NRG Retail LLC, the successor to RRI's Texas retail business, in the six months ended June 30, 2009 and 2010 represented approximately $293 million and $267 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of TXU Energy Retail Company LLC in the six months ended J une 30, 2009 and 2010 represented approximately $79 million and $84 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.

(2)

Included in total assets of Other Operations as of December 31, 2009 and June 30, 2010 are pension and other postemployment related regulatory assets of $731 million and $709 million, respectively.

(16)	Subsequent Events

On July 22, 2010, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.195 per share of common stock payable on September 10, 2010, to shareholders of record as of the close of business on August 16, 2010.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Long-Term Gas Gathering and Treating Agreements

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS) entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from Encana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production. The gathering facilities are known as the “Magnolia Gathering System.”

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place the majority of those facilities in service in the third quarter of 2010 with only well connects remaining. CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. As of June 30, 2010, approximately $286 million has been spent on the original project scope, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat a total volume of up to 1 billion cubic feet (Bcf) per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be approximately $60 million, and the increased capacity is expected to be in service by the first quarter of 2011. In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

CEFS estimates that the capital cost to purchase the existing facilities and construct new facilities for the Olympia Gathering System to gather 600 MMcf per day will be as much as $400 million. As of June 30, 2010, approximately $141 million has been spent on this project, including the purchase of existing facilities. If Encana and Shell elect, CEFS will expand the project to gather and treat additional future volumes of up to 520 MMcf per day, for a total Olympia Gathering System capacity of up to 1.1 Bcf per day. CEFS estimates that the incremental expansion to 1.1 Bcf per day would cost as much as an additional $200 million. Encana and Shell would provide incremental volume commitments in connection with expansions of the Olympia Gathering System.

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Advanced Metering System and Distribution Automation (Intelligent Grid)

In October 2009, the U.S. Department of Energy (DOE) notified CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) that it had been selected for a $200 million grant for its advanced metering system (AMS) and intelligent grid (IG) projects. In March 2010, CenterPoint Houston and the DOE completed negotiations and finalized the agreement. The DOE will reimburse CenterPoint Houston 50% of its eligible costs until the total amount of the grant has been paid. Through June 30, 2010, CenterPoint Houston has requested $42 million of grant proceeds from the DOE of which $33 million has been received. CenterPoint Houston will use $150 million of the grant funding to accelerate completion of its current deployment of advanced meters to 2012, instead of 2014 as originally schedu led. CenterPoint Houston will use the other $50 million from the grant to begin deployment of an electric distribution grid automation strategy in a portion of its service territory over the next three years. It is expected that the portion of the IG project subject to funding by DOE will cost approximately $115 million. CenterPoint Houston believes the IG has the potential to provide a significant improvement in grid planning, operations, maintenance and customer service for its distribution system.

In March 2010, the Internal Revenue Service (IRS) announced through the issuance of Revenue Procedure 2010-20 that it was providing a safe harbor to corporations who receive a Smart Grid Investment Grant. The IRS stated that it would not challenge a corporation’s treatment of the grant as a non-taxable non-shareholder contribution to capital as long as the corporation properly reduced the tax basis of the property acquired with grant funds.

CenterPoint Houston Rate Case

As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Public Utility Commission of Texas (Texas Utility Commission) and the cities in its service area, including cost data and other information that support a retail base rate increase for delivery charges of at least $76 million to the retail electric providers (REPs) that sell electricity to end-use customers in CenterPoint Houston’s service territory. The rate filing package also supports an increase of $18 million for wholesale transmission customers.

In the filing, CenterPoint Houston is also requesting to reconcile its current AMS costs incurred as of March 31, 2010, and to revise the estimated costs to complete the AMS project to reflect $150 million in funds from the $200 million DOE stimulus grant awarded to CenterPoint Houston as discussed above, and updated cost information. The reconciliation plan also requests that the duration of the residential AMS surcharge be shortened by six years from the original 12-year plan.

CenterPoint Houston’s filing seeks a return on equity of 11.25% and proposes that rates be based on a capital structure of 50% equity and 50% long-term debt.

Based on the statutory timeline prescribed for action on rate case filings, we expect that a decision could be rendered by the Texas Utility Commission as early as late 2010.

Equity Offering

In June 2010, we issued 25.3 million shares of our common stock at a price to the public of $12.90 per share. We received net proceeds from the offering of approximately $315 million, after deducting underwriting discounts and offering expenses.

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Financial Reform Legislation

On July 21, 2010 the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), which makes substantial changes to regulatory oversight regarding banks and financial institutions. Many provisions of Dodd-Frank will also affect non-financial businesses such as those conducted by us and our subsidiaries. It is not possible at this time to predict the ultimate impacts this legislation may have on us and our subsidiaries since most of the provisions in the law will require extensive rulemaking by various regulatory agencies and authorities, including, among others, the Securities and Exchange Commission (SEC) and the New York Stock Exchange (NYSE). Nevertheless, in a number of areas, the resulting rules are expected to have direct or indirect impacts on our businesses.

For example, corporate governance provisions in Dodd-Frank will increase required disclosures regarding executive compensation and are expected to result in rules requiring companies to provide shareholders with access to the director nomination process and to submit "say-on-pay" resolutions for consideration by shareholders, perhaps as early as the 2011 annual meeting.

Although Dodd-Frank includes significant new provisions regarding the regulation of derivatives, the impact of those requirements will not be known definitively until regulations have been adopted by the SEC and the Commodities Futures Trading Commission. Nevertheless, from the language of Dodd-Frank and its legislative history, it does not appear that our derivatives trading activities will be subject to substantially more regulation than is currently in place, though the new regulations may increase the costs associated with trading and/or decrease the number of available trading counterparties.

The SEC is charged with adopting new regulations regarding securitization transactions such as those which CenterPoint Houston has sponsored for recovery of stranded costs and costs related to storm restoration. Proposed securitization regulations issued by the SEC before passage of Dodd-Frank would provide exemptions for utility securitizations such as those previously sponsored by CenterPoint Houston from some of the requirements that would be applicable to securitization transactions generally. If those proposed regulations are ultimately adopted to implement Dodd-Frank requirements, similar securitizations sponsored by CenterPoint Houston might not be subject to the regulatory scheme generally prescribed in Dodd-Frank.

Dodd-Frank also makes substantial changes to the regulatory oversight of the credit rating agencies that are typically engaged to rate the securities of us and our subsidiaries. Those provisions include the elimination of certain exemptions the credit agencies have previously enjoyed from liabilities under the securities laws, the treatment of ratings agencies as “experts” when their ratings are used in connection with securities offerings and the elimination of a safe harbor under Regulation FD for information provided to credit rating agencies. Following enactment of Dodd-Frank, the three principal rating agencies announced that they would not consent to the inclusion of their ratings in registered public offerings of securities, but the SEC has issued guidance that mitigates, at least for the present time, t he impacts of the new restrictions on some securities offerings. It is presently unknown what effect implementation of these new provisions ultimately will have on the activities or costs associated with the credit rating process.

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CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2010			2009			2010
Revenues	$	1,640		$	1,756		$	4,406		$	4,779
Expenses		1,387			1,493			3,868			4,159
Operating Income		253			263			538			620
Interest and Other Finance Charges		(129	)		(121	)		(258	)		(243	)
Interest on Transition and System Restoration Bonds		(33	)		(36	)		(66	)		(72	)
Equity in Earnings of Unconsolidated Affiliates		11			7			11			12
Other Income, net		27			13			19			25
Income Before Income Taxes		129			126			244			342
Income Tax Expense		(43	)		(45	)		(91	)		(147	)
Net Income	$	86		$	81		$	153		$	195

Basic Earnings Per Share	$	0.24		$	0.20		$	0.44		$	0.49

Diluted Earnings Per Share	$	0.24		$	0.20		$	0.44		$	0.49

Three months ended June 30, 2010 compared to three months ended June 30, 2009

We reported consolidated net income of $81 million ($0.20 per diluted share) for the three months ended June 30, 2010 compared to $86 million ($0.24 per diluted share) for the same period in 2009. The decrease in net income of $5 million was primarily due to a $14 million decrease related to interest income on Hurricane Ike restoration costs recorded in 2009 included in Other Income, net, a $4 million decrease in the equity in earnings of unconsolidated affiliates and a $2 million increase in income tax expense. These decreases in net income were partially offset by a $10 million increase in operating income (discussed by segment below) and an $8 million decrease in interest expense, excluding transition and system restoration bond-related interest expense.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

We reported consolidated net income of $195 million ($0.49 per diluted share) for the six months ended June 30, 2010 compared to $153 million ($0.44 per diluted share) for the same period in 2009. The increase in net income of $42 million was primarily due to a $82 million increase in operating income (discussed by segment below), a change in net gain (loss) on our indexed debt and marketable securities of $24 million included in Other Income, net and a $15 million decrease in interest expense, excluding transition and system restoration bond-related interest expense. These increases in net income were partially offset by a $56 million increase in income tax expense and a $14 million decrease related to interest income on Hurricane Ike restoration costs recorded in 2009 included in Other In come, net.

Income Tax Expense

During the three and six months ended June 30, 2009, the effective tax rate was 33% and 37%, respectively. During the three and six months ended June 30, 2010, the effective tax rate was 36% and 43%, respectively. The most significant item affecting the comparability of the effective tax rate for the three months ended June 30, 2009 and 2010 is a tax settlement with RRI which occurred on June 30, 2009. The comparability of the effective tax rate for the six months ended June 30, 2009 and 2010 is primarily affected by a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010.

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approximately $11 million, has been recorded as an adjustment to regulatory assets. The remaining $21 million of the reduction in CenterPoint Energy’s deferred tax asset has been reflected as a charge to income tax expense.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (in millions) for each of our business segments for the three and six months ended June 30, 2009 and 2010. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2010			2009			2010
Electric Transmission & Distribution	$	162		$	158		$	232		$	265
Natural Gas Distribution		2			10			120			149
Competitive Natural Gas Sales and Services		6			(6	)		8			9
Interstate Pipelines		61			67			130			139
Field Services		23			31			49			54
Other Operations		(1	)		3			(1	)		4
Total Consolidated Operating Income	$	253		$	263		$	538		$	620

Electric Transmission & Distribution

For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read "Risk Factors ─ Risk Factors Affecting Our Electric Transmission & Distribution Business," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Businesses and Other Risks" in Item 1A of Part II of this Form 10-Q.

The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and six months ended June 30, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues:
Electric transmission and distribution utility	$	432	$	449	$	778	$	835
Transition and system restoration bond companies		89		113		155		209
Total revenues		521		562		933		1,044
Expenses:
Operation and maintenance, excluding transition and system restoration bond companies		181		204		369		394
Depreciation and amortization, excluding transition and system restoration bond companies		69		71		137		144
Taxes other than income taxes		53		52		106		104
Transition and system restoration bond companies		56		77		89		137
Total expenses		359		404		701		779
Operating Income	$	162	$	158	$	232	$	265

Operating Income:
Electric transmission and distribution utility	$	129	$	122	$	166	$	193
Transition and system restoration bond companies (1)		33		36		66		72
Total segment operating income	$	162	$	158	$	232	$	265

Throughput (in gigawatt-hours (GWh)):
Residential		6,831		7,064		10,798		12,237
Total		19,841		20,174		34,983		36,610

Number of metered customers at end of period:
Residential		1,846,908		1,866,699		1,846,908		1,866,699
Total		2,092,209		2,113,695		2,092,209		2,113,695

__________

(1)

Represents the amount necessary to pay interest on the transition and system restoration bonds.

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Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Electric Transmission & Distribution business segment reported operating income of $158 million for the three months ended June 30, 2010, consisting of $122 million from the regulated electric transmission and distribution utility (TDU) and $36 million related to transition and system restoration bond companies. For the three months ended June 30, 2009, operating income totaled $162 million, consisting of $129 million from the TDU and $33 million related to transition bond companies. TDU revenues increased $17 million primarily due to revenues from implementation of AMS ($12 million), higher revenues due to customer growth ($5 million) from the addition of over 21,000 new customers, higher transmission-related revenues ($5 million) and increased usage ($2 million ) in part due to favorable weather, partially offset by a credit to customers related to deferred income taxes associated with Hurricane Ike storm restoration costs ($6 million). Operation and maintenance expenses increased $23 million due primarily to higher transmission costs billed by transmission providers ($7 million) and increased AMS project expenses ($5 million), increased labor and benefit costs ($5 million) and increased insurance costs ($2 million). Increased depreciation expense is related to increased investment in AMS ($5 million) and other capital additions ($1 million), partially offset by reduced transportation equipment depreciation ($4 million) as the account is fully depreciated.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Electric Transmission & Distribution business segment reported operating income of $265 million for the six months ended June 30, 2010, consisting of $193 million from the TDU and $72 million related to transition and system restoration bond companies. For the six months ended June 30, 2009, operating income totaled $232 million, consisting of $166 million from the TDU and $66 million related to transition bond companies. TDU revenues increased $57 million primarily due to increase in use ($28 million), in part caused by favorable weather, revenues from implementation of AMS ($21 million), higher transmission-related revenues ($11 million) and higher revenues due to customer growth ($8 million) from the addition of over 21,000 new customers, partially offset by a customer credit related to deferred income taxes associated with Hurricane Ike storm restoration costs ($12 million). Operation and maintenance expenses increased $25 million primarily due to higher transmission costs billed by transmission providers ($10 million), AMS project expenses ($8 million), increased labor costs ($5 million) and insurance costs ($2 million). Increased depreciation expense is related to increased investment in AMS ($9 million) and other capital additions ($2 million), partially offset by reduced transportation equipment depreciation ($4 million) as described above.

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read "Risk Factors ─ Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Businesses and Other Risks" in Item 1A of Part II of this Form 10-Q.

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The following table provides summary data of our Natural Gas Distribution business segment for the three and six months ended June 30, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues	$	518	$	465	$	1,939	$	2,002
Expenses:
Natural gas		295		244		1,340		1,383
Operation and maintenance		152		144		321		311
Depreciation and amortization		41		44		81		84
Taxes other than income taxes		28		23		77		75
Total expenses		516		455		1,819		1,853
Operating Income	$	2	$	10	$	120	$	149

Throughput (in Bcf):
Residential		20		16		98		112
Commercial and industrial		46		49		123		136
Total Throughput		66		65		221		248

Number of customers at period end:
Residential		2,961,941		2,973,013		2,961,941		2,973,013
Commercial and industrial		241,875		244,089		241,875		244,089
Total		3,203,816		3,217,102		3,203,816		3,217,102

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Natural Gas Distribution business segment reported operating income of $10 million for the three months ended June 30, 2010 compared to $2 million for the three months ended June 30, 2009. Operating income increased $8 million primarily as a result of rate increases ($6 million), lower pension and other benefits costs ($4 million), higher non-volumetric revenues ($2 million) and lower bad debt expense ($2 million). These were partially offset by lower throughput ($4 million), primarily caused by warmer weather, and increased labor costs ($3 million).

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Natural Gas Distribution business segment reported operating income of $149 million for the six months ended June 30, 2010 compared to operating income of $120 million for the six months ended June 30, 2009. Operating income increased $29 million primarily as a result of rate increases ($10 million), higher throughput ($8 million), including the effect of adding 11,000 residential customers, lower bad debt expense ($7 million) in part due to improved collection efforts, lower pension and other benefits costs ($6 million) and increased non-volumetric revenues ($4 million). These were partially offset by higher labor costs ($5 million).

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read "Risk Factors ─ Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Businesses and Other Risks" in Item 1A of Part II of this Form 10-Q.

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The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and six months ended June 30, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2010			2009		2010
Revenues	$	432	$	560		$	1,197	$	1,412
Expenses:
Natural gas		414		554			1,166		1,380
Operation and maintenance		10		10			20		19
Depreciation and amortization		1		1			2		2
Taxes other than income taxes		1		1			1		2
Total expenses		426		566			1,189		1,403
Operating Income (Loss)	$	6	$	(6	)	$	8	$	9

Throughput (in Bcf)		114		128			255		269

Number of customers at period end		10,878		11,694			10,878		11,694

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $6 million for the three months ended June 30, 2010 compared to operating income of $6 million for the three months ended June 30, 2009. The decrease in operating income of $12 million is primarily due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for the second quarter of 2010 of $8 million versus a favorable impact of $3 million for the same period in 2009.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Competitive Natural Gas Sales and Services business segment reported operating income of $9 million for the six months ended June 30, 2010 compared to $8 million for the six months ended June 30, 2009. The increase in operating income of $1 million was due to the improvement of the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for the first six months of 2010 of $5 million versus $16 million for the same period in 2009. A further favorable impact of $5 million is attributable to the $6 million write down of natural gas inventory in the first half of 2009 to the lower of cost or market as compared to a write down of less than $1 million in the first half of 2010. Offsetting these increases to operating income is a $15& #160;million decrease in margin attributable to reduced basis spreads on pipeline transport opportunities and decreased seasonal storage spreads.

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read "Risk Factors ─ Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Businesses and Other Risks" in Item 1A of Part II of this Form 10-Q.

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The following table provides summary data of our Interstate Pipelines business segment for the three and six months ended June 30, 2009 and 2010 (in millions, except throughput data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues	$	155	$	148	$	308	$	286
Expenses:
Natural gas		34		24		63		34
Operation and maintenance		41		35		76		70
Depreciation and amortization		12		13		24		26
Taxes other than income taxes		7		9		15		17
Total expenses		94		81		178		147
Operating Income	$	61	$	67	$	130	$	139

Transportation throughput (in Bcf):		396		400		857		838

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Interstate Pipeline business segment reported operating income of $67 million for the three months ended June 30, 2010 compared to $61 million for the three months ended June 30, 2009. Margins (revenues less natural gas costs) increased $3 million primarily due to new contracts for the phase IV Carthage to Perryville pipeline expansion ($12 million), partially offset by reduced off-system transportation margins and ancillary services ($9 million). Lower operations and maintenance expenses ($6 million) were partially offset by higher depreciation and amortization expenses ($1 million) related to asset additions and increased taxes other than income ($2 million).

Equity Earnings. In addition, this business segment recorded equity income of $9 million and $4 million for the three months ended June 30, 2009 and 2010, respectively, from its 50% interest in the Southeast Supply Header (SESH), a jointly-owned pipeline that went into service in September 2008. The second quarter of 2009 benefited from the receipt of a one-time fee related to the construction of the pipeline and a reduction in estimated property taxes. Our 50% share of those amounts was approximately $5 million. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Interstate Pipeline business segment reported operating income of $139 million for the six months ended June 30, 2010 compared to $130 million for the six months ended June 30, 2009. Margins increased by $7 million primarily due to new contracts for the phase IV Carthage to Perryville pipeline expansion ($24 million) and new power plant transportation contracts ($2 million), partially offset by reduced ancillary services and off-system transportation margins ($19 million). Lower operation and maintenance expenses ($6 million) were partially offset by increased depreciation and amortization expenses ($2 million) related to new assets and increased taxes other than income increased ($2 million).

Equity Earnings. In addition, this business segment recorded equity income of $7 million for both the six months ended June 30, 2009 and 2010, from its 50% interest in SESH. The 2009 results include a non-cash pre-tax charge of $5 million to reflect SESH’s discontinued use of guidance for accounting for regulated operations which was largely offset by the receipt of a one-time fee in the second quarter of 2009 related to the construction of the pipeline and reduced property taxes totaling approximately $5 million. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Field Services

For information regarding factors that may affect the future results of operations of our Field Services business segment, please read "Risk Factors ─ Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Businesses and Other Risks" in Item 1A of Part II of this Form 10-Q.

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The following table provides summary data of our Field Services business segment for the three and six months ended June 30, 2009 and 2010 (in millions, except throughput data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2010		2009		2010
Revenues	$	56	$	80	$	113	$	148
Expenses:
Natural gas		11		18		18		34
Operation and maintenance		18		25		37		46
Depreciation and amortization		3		5		7		11
Taxes other than income taxes		1		1		2		3
Total expenses		33		49		64		94
Operating Income	$	23	$	31	$	49	$	54

Gathering throughput (in Bcf):		102		156		206		284

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Our Field Services business segment reported operating income of $31 million for the three months ended June 30, 2010 compared to $23 million for the three months ended June 30, 2009. Increased margins from new projects and core gathering services ($12 million) and increased commodity prices ($5 million) more than offset the increase in operating expenses ($9 million) associated with new projects.

Equity Earnings. In addition, this business segment recorded equity income of $2 million and $3 million in the three months ended June 30, 2009 and 2010, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Our Field Services business segment reported operating income of $54 million for the six months ended June 30, 2010 compared to $49 million for the six months ended June 30, 2009. Increased margins from new projects and core gathering services ($15 million) and increased commodity prices ($4 million) more than offset the increase in operating expenses ($14 million) associated with new projects.

Equity Earnings. In addition, this business segment recorded equity income of $4 million and $5 million in the six months ended June 30, 2009 and 2010, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Other Operations

The following table shows the operating income (loss) of our Other Operations business segment for the three and six months ended June 30, 2009 and 2010 (in millions):

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2010		2009			2010
Revenues	$	3		$	3	$	6		$	6
Expenses		4			—		7			2
Operating Income (Loss)	$	(1	)	$	3	$	(1	)	$	4

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read "Management’s Discussion and Analysis of Financial Condition and Results of Operations ─ Certain Factors Affecting Future Earnings" in Item 7 of Part II, "Risk Factors" in Item 1A of Part II of this Form 10-Q and "Cautionary Statement Regarding Forward-Looking Information."

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LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2009 and 2010:

	Six Months Ended June 30,
	2009			2010
	(in millions)
Cash provided by (used in):
Operating activities	$	1,056		$	818
Investing activities		(504	)		(719	)
Financing activities		(568	)		(256	)

Cash Provided by Operating Activities

Net cash provided by operating activities in the first six months of 2010 decreased $238 million compared to the same period in 2009 primarily due to decreased cash related to gas storage inventory ($309 million), increased tax payments ($89 million) and increased net margin deposits ($57 million), which were partially offset by increased cash provided by fuel cost recovery ($127 million) and increased net income ($42 million).

Cash Used in Investing Activities

Net cash used in investing activities in the first six months of 2010 increased $215 million compared to the same period in 2009 due primarily to increased capital expenditures ($223 million) primarily related to Field Services projects and increased investment in unconsolidated affiliates ($23 million), which were partially offset by cash received from the DOE grant ($33 million).

Cash Used in Financing Activities

Net cash used in financing activities in the first six months of 2010 decreased $312 million compared to the same period in 2009 primarily due to decreased repayments of borrowings under revolving credit facilities ($932 million), increased proceeds from the issuance of common stock ($182 million) and increased short-term borrowings ($55 million), which were partially offset by decreased proceeds from long-term debt ($500 million), increased payments of long-term debt ($338 million) and increased common stock dividend payments ($21 million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for the remaining six months of 2010 include the following:

•

capital expenditures of approximately $760 million;

•

maturing long-term debt aggregating approximately $200 million;

•

scheduled principal payments on transition and system restoration bonds of $134 million; and

•

dividend payments on CenterPoint Energy common stock and interest payments on debt.

We expect that cash on hand, borrowings under our credit facilities and anticipated cash flows from operations will be sufficient to meet our anticipated cash needs for the remaining six months of 2010. Cash needs or discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

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Off-Balance Sheet Arrangements. Other than operating leases and the guaranties described below, we have no off-balance sheet arrangements.

Prior to the distribution of our ownership in RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. The present value of the demand charg es under these transportation contracts, which will be in effect until 2018, was approximately $89 million as of June 30, 2010. As of June 30, 2010, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

Equity Financing Transactions. During the six months ended June 30, 2010, we received proceeds of approximately $42 million from the sale of approximately 3.1 million shares of common stock to our defined contribution plan and proceeds of approximately $7 million from the sale of approximately 0.5 million shares of common stock to participants in our enhanced dividend reinvestment plan.

Debt Financing Transactions. In January 2010, we purchased $290 million principal amount of pollution control bonds issued on our behalf at 101% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. Prior to the purchase, the pollution control bonds had a fixed rate of interest of 5.125%. The purchase reduces temporary investments and leverage while providing us with the flexibility to finance future capital needs in the tax-exempt market through a remarketing of these bonds.

In January 2010, CERC Corp. redeemed $45 million of its outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Credit and Receivables Facilities. As of July 26, 2010, we had the following facilities (in millions):

Date Executed

Company

Type of

Facility

Size of

Facility

Amount

Utilized at

July 26,

2010 (1)

Termination Date

June 29, 2007

CenterPoint Energy

Revolver

1,156

(2)

June 29, 2012

June 29, 2007

CenterPoint Houston

Revolver

289

(2)

June 29, 2012

June 29, 2007

CERC Corp.

Revolver

915

—

June 29, 2012

October 9, 2009

CERC

Receivables

215

—

October 8, 2010

__________

(1)

Based on the debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant contained in our $1.2 billion credit facility, we would have been permitted to incur incremental borrowings on a consolidated basis at June 30, 2010 of approximately $2.0 billion. The EBITDA covenant would have permitted us to utilize the full capacity of our credit facilities of $2.4 billion at June 30, 2010 if a qualifying natural disaster had occurred during the previous twelve months and securitization financing permitted under Texas law to recover restoration costs

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had not yet occurred. Amounts advanced under CERC’s receivables facility are not treated as outstanding indebtedness in the debt to EBITDA covenant calculation.

(2)

Represents outstanding letters of credit.

Our $1.2 billion credit facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to EBITDA covenant (as those terms are defined in the facility). In February 2010, we amended our credit facility to modify the covenant to allow for a temporary increase of the permitted ratio from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and we certify to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a calendar year, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temp orary increase in the financial ratio covenant would be in effect from the date we deliver our certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of our certification or (iii) the revocation of such certification.

Under our $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and CERC Corp’s $915 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit rating.

Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that we, CenterPoint Houston or CERC Corp. make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we, CenterPoint Houston or CERC Corp. consider customary.

We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective credit facilities as disclosed above.

Our $1.2 billion credit facility backstops a $1.0 billion CenterPoint Energy commercial paper program under which we began issuing commercial paper in June 2005. The $915 million CERC Corp. credit facility backstops a $915 million commercial paper program under which CERC Corp. began issuing commercial paper in February 2008. As a result of the credit ratings on the two commercial paper programs, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements.

Securities Registered with the SEC. In October 2008, CenterPoint Energy and CenterPoint Houston jointly registered indeterminate principal amounts of CenterPoint Houston’s general mortgage bonds and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units. In addition, CERC Corp. has a shelf registration statement covering $500 million principal amount of senior debt securities.

Temporary Investments. As of July 26, 2010, CenterPoint Houston had external temporary investments of $333 million, which excludes funds held in trust for the payment of debt service on transition and system restoration bonds.

Money Pool. We have a money pool through which the holding company and participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under our revolving credit facility or the sale of our commercial paper.

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Impact on Liquidity of a Downgrade in Credit Ratings. The interest on borrowings under our credit facilities is based on our credit rating. As of August 3, 2010, Moody’s Investor Services, Inc. (Moody’s), Standard & Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and Fitch, Inc. (Fitch) had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:

Moody’s

S&P

Fitch

Company/Instrument

Rating

Outlook (1)

Rating

Outlook(2)

Rating

Outlook(3)

CenterPoint Energy Senior

Unsecured Debt

Ba1

Positive

BBB-

Stable

BBB-

Stable

CenterPoint Houston Senior

Secured Debt

Stable

BBB+

Stable

A-

Stable

CERC Corp. Senior Unsecured

Debt

Baa3

Positive

BBB

Stable

BBB

Stable

__________

(1)

A Moody’s rating outlook is an opinion regarding the likely direction of a rating over the medium term.

(2)

An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

(3)

A "stable" outlook from Fitch encompasses a one- to two-year horizon as to the likely ratings direction.

We cannot assure you that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and CERC Corp.’s $915 million credit facility. If our credit ratings or those of CenterPoint Houston or CERC had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at June 30, 2010, the impact on the borrowing costs under our bank credit facilities would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions.

CERC Corp. and its subsidiaries purchase natural gas from one supplier under supply agreements that contain an aggregate credit threshold of $120 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of BBB. Under these agreements, CERC may need to provide collateral if the aggregate threshold is exceeded. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide co llateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of June 30, 2010, the amount posted as collateral aggregated approximately $132 million ($85 million of which is associated with price stabilization activities of our Natural Gas Distribution business segment). Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of June 30, 2010, unsecured credit limits extended to CES by counterparties aggregate $243 million; however, utilized credit capacity was $81 million.

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Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $183 million as of June 30, 2010. The amount of collateral will depend on seasonal variations in transportation levels.

In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion of which $840 million remain outstanding at June 30, 2010. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. common stock (TW Common) attributable to such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. As of June 30, 2010, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of Time Warner Cable Inc. common stock (TWC Common) and 0.045455 share of AOL Inc. common stock (AOL Common). If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common, TWC Common and AOL Common that we own or from other sources. We own shares of TW Common, TWC Common and AOL Common equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because tax deferrals related to the ZENS notes and TW Common, TWC Common and AOL Common shares would typically cease when ZENS notes are exchanged or otherwise retired and TW Common, TWC Common and AOL Common shares are sold. The ultimate tax liability related to the ZENS notes continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes. The American Recovery and Reinvestment Act of 2009 allows us to defer until 2014 taxes due as a result of the retirement of ZENS notes that would have otherwise been payable in 2009 or 2010 and pay such taxes over the period from 2014 through 2018. Accordingly, if on June 30, 2010, all ZENS notes had been exchanged for cash, we could have deferred taxes of approximately $389 million that would have otherwise been payable in 2010.

Cross Defaults. Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. In addition, four outstanding series of our senior notes, aggregating $950 million in principal amount as of June 30, 2010, provide that a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.

Possible Acquisitions, Divestitures and Joint Ventures. From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures or other joint ownership arrangements with respect to assets or businesses. Any determination to take any action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by:

•

cash collateral requirements that could exist in connection with certain contracts, including our weather hedging arrangements, and gas purchases, gas price and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments;

•

acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;

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•

increased costs related to the acquisition of natural gas;

•

increases in interest expense in connection with debt refinancings and borrowings under credit facilities;

•

various legislative or regulatory actions;

•

incremental collateral, if any, that may be required due to regulation of derivatives;

•

the ability of RRI and its subsidiaries to satisfy their obligations in respect of RRI’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which CERC is a guarantor;

•

the ability of REPs that are subsidiaries of NRG Retail LLC and TXU Energy Retail Company LLC, which are CenterPoint Houston’s two largest customers, to satisfy their obligations to us and our subsidiaries;

•

slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;

•

the outcome of litigation brought by and against us;

•

contributions to pension and postretirement benefit plans;

•

restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and

•

various other risks identified in “Risk Factors” in Item 1A of Part II of this Form 10-Q.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money. CenterPoint Houston’s credit facilities limit CenterPoint Houston’s debt (excluding transition and system restoration bonds) as a percentage of its total capitalization to 65%. CERC Corp.’s bank facility and its receivables facility limit CERC’s debt as a percentage of its total capitalization to 65%. Our $1.2 billion credit facility contains a debt, excluding transition and system restoration bonds, to EBITDA covenant. In February 2010, we amended our $1.2 billion credit facility to modify this covenant to allow for a temporary increase in debt capacity if CenterPoint Houston experiences damage from a natural disaster in its service territory that meets certain criteria. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Consolidated Financial Statements for a discussion of new accounting pronouncements that affect us.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk From Non-Trading Activities

We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis. The sensitivity analysis performed on our non-trading energy derivatives measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. At June 30, 2010, the recorded fair value of our non-trading energy derivatives was a net liability of $142 million (before collateral). The net liability consisted of a net liability of $157 million associated with price stabilization activities of our Natu ral Gas Distribution business segment and a net asset of $15 million related to our Competitive Natural Gas Sales and Services business segment. Net assets or liabilities related to the price stabilization activities correspond directly with net over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the market prices of energy commodities from their June 30, 2010 levels would have increased the fair value of our non-trading energy derivatives net liability by $24 million. However, the

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consolidated income statement impact of this same 10% decrease in market prices would be a decrease in income of $3 million.

The above analysis of the non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate or on our recovery through price stabilization activities. Furthermore, the non-trading energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.

Interest Rate Risk

As of June 30, 2010, we had outstanding long-term debt, bank loans, lease obligations and obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.

We had no floating-rate obligations at December 31, 2009 and June 30, 2010.

At December 31, 2009 and June 30, 2010, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $9.9 billion and $9.5 billion, respectively, in principal amount and having a fair value of $10.4 billion and $10.3 billion, respectively. Because these instruments are fixed-rate, they do not expose us to the risk of loss in earnings due to changes in market interest rates (please read Note 13 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $221 million if interest rates were to decline by 10% from their levels at June 30, 2010. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

The ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $124 million at June 30, 2010 was a fixed-rate obligation and, therefore, did not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $20 million if interest rates were to decline by 10% from levels at June 30, 2010. Changes in the fair value of the derivative component, a $196 million recorded liability at June 30, 2010, are recorded in our Condensed Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% fro m June 30, 2010 levels, the fair value of the derivative component liability would increase by approximately $4 million, which would be recorded as an unrealized loss in our Condensed Statements of Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 7.2 million shares of TW Common, 1.8 million shares of TWC Common and 0.7 million shares of AOL Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the June 30, 2010 aggregate market value of these shares would result in a net loss of approximately $7 million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2010 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such

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information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 4 and 11 to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also "Business ─ Regulation" and "─ Environmental Matters" in Item 1 and "Legal Proceedings" in Item 3 of our 2009 Form 10-K.

Item 1A. RISK FACTORS

The following risk factors are provided to supplement and update the risk factors contained in the reports we file with the SEC, including the risk factors contained in Item 1A of Part I of our 2009 Form 10-K.

We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC Corp. The following information about risks, along with any additional legal proceedings identified or referenced in Part II, Item 1 “Legal Proceedings” of this Form 10-Q and in “Legal Proceedings” in Item 3 of our 2009 Form 10-K, summarize the principal risk factors associated with the businesses conducted by each of these subsidiaries.

Risk Factors Affecting Our Electric Transmission & Distribution Business

Following the exhaustion of all judicial appeals in its true-up proceeding, CenterPoint Houston may lose certain tax benefits and/or may not recover the full amount of its true-up request. Such a result could have an adverse impact on CenterPoint Houston’s results of operations, financial condition and cash flows.

•

reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

•

reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers (REPs); and

•

affirmed the True-Up Order in all other respects.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

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•

reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

•

ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

•

affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i) denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true-up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true up award.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision. Oral argument before the court was held in October 2009, and the parties have filed post-submission briefs to the court. Although we and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its appeal to the Texas Supreme Court, we can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, we recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-Up Order, but could range from $180 million to $410 million (pre-tax) plus interest subsequent to December 31, 2009.

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CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, we received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require us to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on our results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issu e be remanded to the Texas Utility Commission, as that commission requested. No party has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. We and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

CenterPoint Houston’s receivables are concentrated in a small number of REPs, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.

CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. As of June 30, 2010, CenterPoint Houston did business with approximately 92 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which CenterPoint Houston c an apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and thus remains at risk for payments not made prior to the shift to the provider of last resort. The Texas Utility Commission revised its regulations in 2009 to (i) increase the financial qualifications from REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. A subsidiary of NRG Energy, Inc., NRG Retail LLC, acquired the Texas retail business of RRI, and its subsidiaries are together considered the largest REP in CenterPoint Houston’s service territory. Approximately 39% of CenterPoint Houston’s $200 million in billed receivables from REPs at June 30, 2010 was owed by subsidiaries of NRG Retail LLC and approximately 13% of the $200 million in billed receivables was owed by subsidiaries of TXU Energy Retail Company LLC (TXU Energy). Any delay or default in payment by REPs could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made by creditors involving payments CenterPoint Houston had received from such REP.

Rate regulation of CenterPoint Houston’s business may delay or deny CenterPoint Houston’s ability to earn a reasonable return and fully recover its costs.

CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.

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Disruptions at power generation facilities owned by third parties could interrupt CenterPoint Houston’s sales of transmission and distribution services.

CenterPoint Houston transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston’s sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows could be adversely affected.

CenterPoint Houston’s revenues and results of operations are seasonal.

A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, CenterPoint Houston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.

Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses

Rate regulation of CERC’s business may delay or deny CERC’s ability to earn a reasonable return and fully recover its costs.

CERC’s rates for its natural gas distribution business (Gas Operations) are regulated by certain municipalities and state commissions, and for its interstate pipelines by the Federal Energy Regulatory Commission, based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC’s costs and enable CERC to earn a reasonable return on its invested capital.

CERC’s businesses must compete with alternate energy sources, which could result in CERC marketing less natural gas, and its interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices and reduced volumes, either of which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC’s two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. The actions of CERC’s competitors could lead to lower prices, which may have an adverse impact on CERC’s results of operations, financial condition and cash flows. Additionally, any reduction in the volume of natural gas transported or stored may have an adverse impact on CER C’s results of operations, financial condition and cash flows.

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CERC’s natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas prices, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity and results of operations.

CERC is subject to risk associated with changes in the price of natural gas. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could (i) apply downward demand pressure on natural gas consumption in the areas in which CERC operates thereby resulting in decreased sales and transportation volumes and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase CERC’s working capital requirements by increasing the investment that must be made in or der to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that CERC must provide under its hedging arrangements.

A decline in CERC’s credit rating could result in CERC’s having to provide collateral in order to purchase natural gas or under its shipping or hedging arrangements.

If CERC’s credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas or under its shipping or hedging arrangements. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s results of operations, financial condition and cash flows could be adversely affected.

The revenues and results of operations of CERC’s interstate pipelines and field services businesses are subject to fluctuations in the supply and price of natural gas and natural gas liquids and regulatory and other issues impacting our customers’ production decisions.

CERC’s interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by our gathering and pipeline transportation systems and our natural gas treating and processing activities. A sustained decline could also lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production co sts relative to other available production, producers’ access to needed capital and the cost of that capital, access to drilling rigs, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Regulatory changes include the potential for more restrictive rules governing the use of hydraulic fracturing, a process used in the extraction of natural gas from shale reservoir formations, and the use of groundwater in that process. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves or to shut in production from existing reserves. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on CERC’s results of operations, financial condition and cash flows.

CERC’s results of operations from these businesses are also affected by the prices of natural gas and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.

CERC’s revenues and results of operations are seasonal.

A substantial portion of CERC’s revenues is derived from natural gas sales and transportation. Thus, CERC’s revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.

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The actual cost of pipelines under construction, future pipeline, gathering and treating systems and related compression facilities may be significantly higher than CERC had planned.

Subsidiaries of CERC Corp. have been recently involved in significant pipeline construction projects and, depending on available opportunities, may, from time to time, be involved in additional significant pipeline construction and gathering and treating system projects in the future. The construction of new pipelines, gathering and treating systems and related compression facilities may require the expenditure of significant amounts of capital, which may exceed CERC’s estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, whic h could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve CERC’s expected investment return, which could adversely affect CERC’s financial condition, results of operations or cash flows.

The states in which CERC provides regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to or broader than those under the Public Utility Holding Company Act of 1935 regarding organization, financing and affiliate transactions that could have significant adverse impacts on CERC’s ability to operate.

The Public Utility Holding Company Act of 1935, to which we and our subsidiaries were subject prior to its repeal in the Energy Policy Act of 2005, provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, some states in which CERC does business have sought to expand their own regulatory frameworks to give their regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility business that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.

These regulatory frameworks could have adverse effects on CERC’s ability to conduct its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for CERC and us to comply with competing regulatory requirements.

Risk Factors Associated with Our Consolidated Financial Condition

If we are unable to arrange future financings on acceptable terms, our ability to refinance existing indebtedness could be limited.

As of June 30, 2010, we had $9.6 billion of outstanding indebtedness on a consolidated basis, which includes $2.9 billion of non-recourse transition and system restoration bonds. As of June 30, 2010, approximately $815 million principal amount of this debt is required to be paid through 2012. This amount excludes principal repayments of approximately $724 million on transition and system restoration bonds, for which a dedicated revenue stream exists. Our future financing activities may be significantly affected by, among other things:

•

the resolution of the true-up proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;

•

general economic and capital market conditions;

•

credit availability from financial institutions and other lenders;

•

investor confidence in us and the markets in which we operate;

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•

maintenance of acceptable credit ratings;

•

market expectations regarding our future earnings and cash flows;

•

market perceptions of our ability to access capital markets on reasonable terms;

•

our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us;

•

incremental collateral that may be required due to regulation of derivatives; and

•

provisions of relevant tax and securities laws.

As of June 30, 2010, CenterPoint Houston had outstanding approximately $2.5 billion aggregate principal amount of general mortgage bonds, including approximately $527 million held in trust to secure pollution control bonds for which we are obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.1 billion of a dditional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of June 30, 2010. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Our current credit ratings are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries — Liquidity and Capital Resources — Future Sources and Uses of Cash — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 2 of Part I of this Form 10-Q. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

As a holding company with no operations of our own, we will depend on distributions from our subsidiaries to meet our payment obligations, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.

Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could negatively impact our results of operations and those of our subsidiaries.

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial

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instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Risks Common to Our Businesses and Other Risks

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•

restricting the way we can handle or dispose of wastes;

•

limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

•

requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and

•

enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

•

construct or acquire new equipment;

•

acquire permits for facility operations;

•

modify or replace existing and proposed equipment; and

•

clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system, other than substations, because CenterPoint

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Houston believes it to be cost prohibitive. In the future, CenterPoint Houston may not be able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other natural disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise, or any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

We, CenterPoint Houston and CERC could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or through subsidiaries and include:

•

merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and

•

Texas electric generating facilities transferred to Texas Genco Holdings, Inc. (Texas Genco) in 2004 and early 2005.

In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liabil ity in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.

Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $89 million a s of June 30, 2010. As of June 30, 2010, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI’s creditors might be made against us as its former owner.

In May 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. and no longer provides service as a REP in CenterPoint Houston’s service territory. In April 2010, RRI announced its plan to merge with Mirant Corporation in an all-stock transaction. Neither the sale of the retail business nor the merger with Mirant Corporation, if ultimately finalized, alters RRI’s contractual obligations to indemnify us and our subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts.

Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of sales of natural gas in California and other markets. Although these matters relate to the business and operations of RRI, claims against

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Reliant Energy have been made on grounds that include liability of Reliant Energy as a controlling shareholder of RRI. We, CenterPoint Houston or CERC could incur liability if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Houston or CERC and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.

In connection with the organization and capitalization of Texas Genco, Reliant Energy and Texas Genco entered into a separation agreement in which Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were obligations of CenterPoint Houston, and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historica l businesses and operations of Texas Genco, regardless of the time those liabilities arose. If Texas Genco were unable to satisfy a liability that had been so assumed or indemnified against, and provided we or Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.

In connection with our sale of Texas Genco to a third party, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and we would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by us. Texas Genco and its related businesses now operate as subsidiaries of NRG Energy, Inc.

We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by NRG Texas LP. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from us and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of th e costs of such defense by NRG Texas LP.

The unsettled conditions in the global financial system may have impacts on our business, liquidity and financial condition that we currently cannot predict.

The recent credit crisis and unsettled conditions in the global financial system may have an impact on our business, liquidity and financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facilities, should they further occur, could adversely affect our liquidity. Capital market turmoil was also reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of our pension plan. These reductions in creased non-cash pension expense in 2009 which impacted 2009 results of operations and may impact liquidity if contributions are made to offset reduced asset values.

In addition to the credit and financial market issues, a recurrence of national and local recessionary conditions may impact our business in a variety of ways. These include, among other things, reduced customer usage, increased customer default rates and wide swings in commodity prices.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our services.

Legislation to regulate emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the EPA has

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undertaken new efforts to collect information regarding greenhouse gas emissions and their effects. Recently, the EPA declared that certain greenhouse gases represent an endangerment to human health and proposed to expand its regulations relating to those emissions. It is too early to determine whether, or in what form, further regulatory action regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory action might have on us and our subsidiaries. However, as a distributor and transporter of natural gas and consumer of natural gas in its pipeline and gathering businesses, CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

Climate changes could result in more frequent severe weather events and warmer temperatures which could adversely affect the results of operations of our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. Another possible climate change is the possibility of more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Common Stock Award to Chairman. In June 2010, we awarded Milton Carroll, our non-executive Chairman of the Board of Directors, 25,000 shares of our common stock pursuant to his compensation arrangements. We relied on a private placement exemption from registration under Section 4(2) of the Securities Act of 1933.

Item 5. OTHER INFORMATION

The ratio of earnings to fixed charges for the six months ended June 30, 2009 and 2010 was 1.70 and 2.05, respectively. We do not believe that the ratios for these six-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

We were successful at reaching an agreement with the International Brotherhood of Electric Workers (IBEW) Union Local 66 for a new three year contract effective May 26, 2010. The IBEW Local 66 members ratified the agreement in a vote held on July 1, 2010.

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Item 6. EXHIBITS

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.

Agreements included as exhibits are included only to provide information to investors regarding their terms. Agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and no such agreement should be relied upon as constituting or providing any factual disclosures about CenterPoint Energy, Inc., any other persons, any state of affairs or other matters.

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1	─	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
3.2	─	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated January 20, 2010	1-31447	3.1
4.1	─	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	─	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3.1	─	$1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.3
4.3.2	─	First Amendment to Exhibit 4.3.1, dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	4.4
4.3.3	─	Second Amendment to Exhibit 4.3.1, dated as of November 18, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.1
4.3.4	─	Third Amendment to Exhibit 4.3.1, dated as of February 5, 2010, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated February 5, 2010	1-31447	4.1
4.4.1	─	$300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.4.2	─	First Amendment to Exhibit 4.4.1, dated as of November 18, 2008, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.2

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Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
4.5	─	$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.5
+12	─	Computation of Ratios of Earnings to Fixed Charges
+31.1	─	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	─	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	─	Section 1350 Certification of David M. McClanahan
+32.2	─	Section 1350 Certification of Gary L. Whitlock
+101.INS	─	XBRL Instance Document (1)
+101.SCH	─	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	─	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	─	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	─	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)

Furnished, not filed.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CENTERPOINT ENERGY, INC.


By:	/s/ Walter L. Fitzgerald
	Walter L. Fitzgerald
	Senior Vice President and Chief Accounting Officer

Date: August 4, 2010

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Index to Exhibits

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1	─	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
3.2	─	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated January 20, 2010	1-31447	3.1
4.1	─	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	─	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3.1	─	$1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.3
4.3.2	─	First Amendment to Exhibit 4.3.1, dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	4.4
4.3.3	─	Second Amendment to Exhibit 4.3.1, dated as of November 18, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.1
4.3.4	─	Third Amendment to Exhibit 4.3.1, dated as of February 5, 2010, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated February 5, 2010	1-31447	4.1
4.4.1	─	$300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.4.2	─	First Amendment to Exhibit 4.4.1, dated as of November 18, 2008, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.2

Table of Contents

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
4.5	─	$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.5
+12	─	Computation of Ratios of Earnings to Fixed Charges
+31.1	─	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	─	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	─	Section 1350 Certification of David M. McClanahan
+32.2	─	Section 1350 Certification of Gary L. Whitlock
+101.INS	─	XBRL Instance Document (1)
+101.SCH	─	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	─	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	─	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	─	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)

Furnished, not filed.

Unassociated Document

Exhibit 12

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)

	Six Months Ended June 30,
	2009 (1)			2010 (1)

Net Income	$	153		$	195
Equity in earnings of unconsolidated affiliates, net of distributions		(8	)		6
Income taxes		91			147
Capitalized interest		(3	)		(3	)
		233			345

Fixed charges, as defined:

Interest		324			315
Capitalized interest		3			3
Interest component of rentals charged to operating expense		5			12
Total fixed charges		332			330

Earnings, as defined	$	565		$	675

Ratio of earnings to fixed charges		1.70			2.05

(1)	Excluded from the computation of fixed charges for the six months ended June 30, 2009 and 2010 is interest expense of $9 million and $4 million, respectively, which is included in income tax expense.

ex31-1.htm

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 4, 2010

	/s/ David M. McClanahan
	David M. McClanahan
	President and Chief Executive Officer

ex31-2.htm

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 4, 2010

	/s/ Gary L. Whitlock
	Gary L. Whitlock
	Executive Vice President and Chief Financial Officer

ex32-1.htm

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2010 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David M. McClanahan
David M. McClanahan
President and Chief Executive Officer
August 4, 2010

ex32-2.htm

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2010 (the “Report”), as filed with the Securities and xchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Gary L. Whitlock
Gary L. Whitlock
Executive Vice President and Chief Financial Officer
August 4, 2010